Oil recovery, particularly from economically marginal wells, is enhanced by injecting a fracturing material, typically polymer-gelled water mixed with sand, into the wellbore. The fracturing fluid is forced under pressure into the producing formation, hydraulically inducing fractures, and the fractures are propped open by the proppant, such as the sand. Known proppant alternatives to sand include glass beads and certain ceramics. That known process enhances production by permitting oil more distant from the hole to flow to the wellbore, from which it can flow or be pumped to the surface.
The oilfield industry often uses phenolic resin coating on proppants in such downhole reservoir fracture stimulation procedures. Presently, the oil industry uses millions of pounds of resin-coated proppant per year for fracturing treatments.
Typically, after placement into the reservoir fracture, the resin coating on the proppant undergoes physicochemical change due to temperature and reaction with a chemical activator. The activator hastens the process first by softening the resin coat, which becomes sticky. Next, the resin-coated proppant material congeals into a hardened, permeable mass, thus inducing bonding of the packed proppant in the fracture. Such hardening is useful because (1) it helps reduce proppant migration from the fracture into the wellbore, which is undesired because it can cause granular erosion and sticking of the pump and other equipment during subsequent production, and (2) it reduces the likelihood of crushing within the fracture, which is undesired because it results in fine debris and increased fracture closure, thereby reducing fluid flow to the wellbore. The net result of the process is a polymer filter pack around the wellbore, which facilitates long-term pumping and enhanced fluid production rates.
In known hydraulic fracturing processes, the chemical activator and the resin-coated proppant are mixed at the surface and pumped into the hole together.
A common problem associated with activated resin-coated proppant occurs from premature "screenout," which is caused by excessive fluid bleedoff of the fracturing gel into the surrounding formation rock. Screenout causes chemically activated resin-coated sand in the fracturing gel to pack the fracture and extend back into the wellbore. The proppant thus becomes concentrated in the wellbore as sticky, cohesive plugs. If screenout occurs before the fracturing treatment is completed, the plugs will block entry of further proppant and cause abrupt increases in injection pressures.
To improve reservoir stimulation success, operators often use relatively low pump-injection rates to minimize or control the growth of hydraulic fractures. Premature screenout also often occurs during low-rate fracturing treatments. Premature screenout frequently occurs in higher-permeability reservoirs and in association with relatively high proppant concentrations in the fracturing fluid.
During many hydraulic fracture treatments, and particularly during real-time tracer monitoring of fracture treatments (as disclosed in my U.S. Pat. Nos. 5,322,126, 5,413,179, and 5,441,110), a tubing string and associated mechanical packers and retrievable bridge plugs are present in the wellbore. As a result of premature screenout, the tubing and associated wellbore tools frequently become stuck by the chemically activated resin-coated proppant. That occurrence significantly complicates the situation, frequently resulting in expensive fishing operations to retrieve stuck tubing and wellbore tools.
Premature screenout causes severe economic consequences to the operator. Sometimes wells are permanently lost or damaged when fishing or cleaning operations are unsuccessful, particularly when activated resin-coated proppant is used. Premature screenout is a problem preferably avoided by careful design of the hydraulic fracturing treatment, but in reality the occurrence of premature screenout is difficult to predict or consistently avoid by design. As a result, many operators are reluctant to pump chemical activator in the fracturing fluid from the surface, as is the common industry method, because of the risks of ruining the well or causing expensive remedial work. That reluctance itself may result in lost production, if the process would have worked to enhance the oil production from the well.
Presently, an operator observes screenout by noting, using existing monitoring techniques, an increase in injection pressures monitored at the surface, or an increase in the bottomhole treating pressure via downhole measurement devices. Depending on circumstances, the operator may (1) immediately switch from the proppant-slurry pumping stage to the flush stage minus sand proppant, (2) increase the pumping rate, or (3) abruptly terminate the fracturing treatment.
The option of increasing the pumping rate is intended to overcome the fluid bleedoff rates in the fracture. Often, a timely rate increase overcomes fluid loss in the formation or increases induced fracture width, allowing the treatment to be completed. Otherwise, the increased pressures forces the operator to shut down the pumping procedure abrubtly and respond with immediate remedial action to circulate the sand proppant out of the hole. Immediate circulation is often difficult, however, because of the hydrostatic pressure of the heavily sand-laden fluid in the hole, often combined with continuous fluid seepage into the fracture-stimulated reservoir. Also, increased pumping rates may cause the fractures to extend out of the producing zone, causing subsequent excessive water influx into the wellbore or otherwise ruining the well. Thus, present techniques of responding to premature screenout may fail to permit continued proppant injection or even worsen the problem.
It is, therefore, a primary object of the invention to permit the use of selectively activated resin-coated proppant with reduced risk of premature screenout.
It is another object of the invention to improve the production from oil and gas wells.
It is another object of the invention to promote the successful completion of hydraulic fracturing treatments.
It is another object of the invention to allow the use of resin-coated proppant without risking stuck tubing or wellbore tools.
It is another object of the invention to permit the more safe use of hydraulic fracturing treatments while downhole equipment and tubing is present in the hole.
It is another object of the invention to permit the more safe use of hydraulic fracturing treatments that have low injection rates or high proppant concentration, or that are directed to high-permeable reservoirs.
It is another object of the invention to facilitate the precise, concentrated placement of chemical activation and to improve the quality and fluid conductivity of the proppant-packed fracture system adjacent to the wellbore.
It is another object of the invention to reduce the quantity and cost of chemical activator associated with fracturing treatments.
It is another object of the invention to prevent or more easily cure detrimental and potentially hazardous side effects associated with fracturing treatments.